Evolution Petroleum Corp (EPM) 2009 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the Evolution Petroleum's fiscal fourth quarter earnings conference call.

During today's presentation all parties will be in a listen-only mode. Following the presentation the conference will be open for questions. As a reminder this call is being recorded today, September 16, 2009. (Operator Instructions).

I would now like to turn the conference over to Ms. Lisa Elliott with DRG&E. Please go ahead, maam.

Thank you and good morning, everyone. We appreciate you joining us for Evolution Petroleum's conference call to discuss results for the fourth quarter and for full year of fiscal 2009 which ended June 30.

Before I turn the call over to management I do have a few items to go over. If you would like to be on the Company's e-mail distribution list to receive future news releases, please call DRG&E's office (713) 529-6600 and someone will be glad to help you. If you wish to listen to a replay of today's call it will be available in a few hours via webcast by going to the Company's website. That's www.evolutionpetroleum.com or via recorded replay until September 23, 2009. And to use that replay feature call (303) 590-3030 and dial the pass code 415-9937. Information recorded on this call is valid only as of today, September 16, 2009, and therefore time sensitive information may no longer be accurate as of the date of any replay. Today management's going to discuss certain topics that may contain forward-looking information which are based on management's beliefs as well as assumptions made by management and information currently available to management. Forward-looking information includes statements regarding expected future drilling results, production and expenses.

Although management beliefs and expectations reflected in such forward-looking statements are reasonable they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks and uncertainties and assumptions which are listed and described in the Company's filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlining assumptions prove incorrect actual results may differ materially from those expected. Also today's call may include discussion of probable and possible reserves or use terms like "volume", "reserve potential" or "recoverable reserves". The SEC generally only allows disclosure of proved reserves in security filings and these estimates of nonproved reserves or resources are by their very nature more speculated than estimates to proved reserves and accordingly, are subject to substantially greater risks.

Now I would like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob.

Thanks, Lisa, and good morning to everyone. Thanks for joining us today. With us this morning is our CFO, Sterling McDonald.

In addition to reviewing our fourth quarter and full-year financial results we will also discuss our year-end reserves that we reported on last week. I'd like to also remind everyone that available on our website is our most recent presentation with much of the same information. As you may have noted in the release last week, we reported that our total proved and probable oil gas reserves were 17.8 million BOE in a pretax TB10 of $244 million. Of course that's based on prices in effect - - constant prices in effect as of July 1. We're quite pleased with what we've accomplished over the last year, particularly since our founding in 2003 given that we only started with about a million in capital back in September of 2003 and about about $8 million total paid in equity since our start-up. This year for the first time we engaged DeGolyer & McNaughton, our independent reservoir engineer to evaluate our interest in the Delhi Field to enhance all recovery of the project, which is being operated and funded by Denbury Resources. D&M assigned 13.6 million barrels of oil - - probable reserves net to our interest with a pretax PB10 of $196.6 million, that's based on a $66.62 oil price.

Now of our total 1P and 2P reserves, 17% are proved, and 91% are crude oil, condensate or gas liquids. Meaning all those are tied to oil price. Now 83% of our reserves are in the probable category. But keep in mind that these are really what we consider to be high quality probable reserves. For example the reserves associated with the Delhi project are projected to be a candidate for upgrading to proved category in 2010 when either the new SEC definitions of proved reserves go into effect or following first production response, whichever comes first. The probable reserves in the Giddings Field in central Texas are primarily associated with proved drilling locations or they offset our best well drilled to date. And our probable reserves in the Neptune project in south Texas are associated with infill development wells that are patterned after historical results. Now year-end 2009 or June 30, our proved reserves totaled 3.1 million barrels of oil equivalent of which 65% are crude oil related, crude oil [consair] NGO. In the pretax TB10 there's almost $36 million.

We had reserve additions of 291 MBOE, these are associated primarily with two new drilling locations in the Giddings Field and our first four proved locations in south Texas. Now we had downward revisions of 1.1 million BOE, and this is all associated with the decline in NYMEX commodity prices, primarily gas. Our gas prices year-over-year declined some 70% for gas and 50% for oil. As you may remember, commodity prices hit their peek right on about July 1 of 2008 when we do our reserves. Given that fact, we're very pleased that we didn't - - not only did we not have to write down our full cost pull during the fiscal year but we still retained quite a bit of a cushion of PB10s over costs. Now the reserve revisions that we experienced were primarily the result of five locations in dropped off proved reserves that were all - - essentially all natural gas and content. These are all in the Giddings Field and these actually would go back onto our proved reserves lists as gas prices head back to, say, a $6 price because we still retain the leases.

Our 2009 proved reserves were net of 134 MBOE of production during the year, and should say all of that came from the Giddings Field. Now going forward as we enter fiscal 2010 our net production is running about 366 BOE a day net, and this is all coming from ten wells in the Giddings Field. Now about a third of that is natural gas. And as a result we have just elected to defer drilling there until we see gas prices recover later, we expect in fiscal 2010. Of course we don't control gas price. Our objectives in the Giddings Field during fiscal 2010 are to focus on workovers and also to drill a single disposal well for water to optimize our production and reduce lifting costs. We expect to generate cash flow from our Giddings operations that we think will be sufficient to cover our cash overhead costs going forward during the fiscal year.

Earlier in the year, in the calendar year of 2009, we stated that we expected meaningful cash flow by Delhi by late calendar 2009. Unfortunately, we've had a small delay there in Denbury's operation, related to their pipeline, the CO2 pipeline to Delhi. Denbury recently reported that first injection may be delayed by up to 3 months in order to complete a minor modification to that pipeline. If that occurs, then first CO2 injection probably won't occur until sometime in the fourth quarter, fourth calendar quarter of 2009 since oil production response isn't expected to occur for up to six months after the first injection. That would put our first oil production response sometime in mid-2010 calendar year. Our initial revenues from this project will come from our 7.4% royalty interest. Since that royalty interest bears no operating expense or capital, those cash flows are going to fall directly to the bottom line. We expect to generate a cash flow in fiscal 2010 from our Neptune project, which will be oil revenues.

Now we are very pleased to report that we have first assigned proved reserves to our Neptune project in south Texas. And these - - this is a combination of proved, probable and possible reserves. This is our Neptune-[Marley] heavy oil project. To give you a little background, this field was developed many decades ago with about 380 wells that produced approximately 32 million barrels of oil. Previous operator also drilled 11 infill wells back in the 1970's and demonstrated that such infill drilling could yield reserves that approached that of the original wells. Now softness in oil prices during the 1990's led to the field being totally plugged and abandoned some years ago. Based on the historical data and oil prices that we see now, our independent reservoir engineer has given us about half a million barrels of proved, probable and possible oil reserves with a pretax PV-10 of a little over $8 million. And these reserves are associated with just the very first 25 proved locations, proved and probable locations. Keep in mind that we have only vested a little over a half a million dollars to date.

What's really exciting in this field is that we have another 79 locations to drill, infill - - prospective infill drilling locations on our acreage alone. Now we believe that the risk in this project is primarily associated with engineering and oil prices and not exploration, and this is confirmed by our operating and drilling results in a very similar field in Louisiana that was developed on very much smaller spacing per well. These vertical wells in Neptune are projected to require average drilling and completion costs of about, oh, a little over a quarter million dollars per well, including water disposal. And while our reserves report projects about 22,000 barrels of oil net to our interest per well, historical results suggest that there is potential for a far greater recovery per well. Now based on the reserves report our finding development cost is therefore, oh, roughly $11 net barrel of oil. Our current budget calls for us this fiscal year to drill our first two producing wells and one injection well, and this activity will begin shortly. We expect to generate revenue from the Neptune project sometime starting the second quarter of fiscal 2010, and these wells will help offset declines in the Giddings Field.

There are other projects, up in Oklahoma, eastern Oklahoma, we're proceeding with our field test program beginning with our shallow acreage in Wagner County which is just outside of Tulsa. Now late in fiscal 2009, say in June, we drilled three new vertical wells and we re-entered three vertical wells and we also obtained our first full core. We're very pleased with the results, or our initial results so far, as these preliminarily tests show that the Woodford Shale is present and productive with good reservoir characteristics. As a plus, the core test combined with log analysis indicated that there's a second shale reservoir that also has very favorable characteristics for development in conjunction with the Woodford. Consequently, we have tested the Woodford and the - - four of these wells, and we've tested the other shale in two of the wells and we've demonstrated commercial production in both reservoirs.

Going forward, we're going to conduct extended production tests of both shale reservoirs following completion with hydraulic fracturing with a full sand profit. Later in the fiscal year we plan to test the two shale reservoirs on our substantial acreage position to the south in Haskel County where we have another 8,000 plus acres. And these shales are located between 4,000 to 5,000 foot compared to the 1,200 to 1,800 foot depth in our Wagner County acreage. Now our level of activity in Oklahoma is going to dependent on natural gas prices. We believe there are 17,000 plus net acres hold up to 200 net BCF of shale gas potential at development costs of somewhere in the $0.75 to $1.25 range per MCF. However we expect to defer full development until we see better gas prices. Same concept as before, that we just don't want to waste our shareholder value at low gas prices. For now we're really concentrating on proving up the play instead of producing the natural gas.

Revenue in our fourth quarter of 2009 declined 26% from the third quarter of 2009 due to our best well being offline for about half the quarter due to compressor downtime by our gas purchaser, as well as normal decline in no new drilling. And that sequential revenue reduction was offset by a 14% improvement in the average sales price per BOE, primarily due to oil prices offset by lower gas prices. Now because we were actively drilling early in year our revenues for first - - for the 12 months of 2009 increased by some 43% over the prior fiscal year to over $6 million, on increases 160% increase in production volumes. Now this revenue growth was offset partially by a 45% decrease in the blended oil and gas price we received. Again, no one wants to generate losses either for the quarter or for the year but we believe that it's in the best interests of our shareholders to follow this conservative strategy of not investing money to produce low-price gas. We would rather keep that gas in the ground until we get a little better market.

Now with that, we're going to - - I'll turn this over to Sterling to talk about our financial results.

Thanks, Bob. And thanks to all of you for joining us today. And hopefully you've had a chance to review the earnings release we put out this morning and I won't read the numbers to you.

But I would like to give you some highlights for 2009, and looking into 2010. As Bob mentioned, our sales volumes increased 169% in 2009 versus 2008. We entered 2010 in a combined rate of approximately 366 BOE net a day of production. We did a good job of growing our production volumes and controlling our costs but we were negatively impacted by the steep decline in commodity prices and, as a result, we had a net loss of $0.03 per share in the fiscal fourth quarter and a loss of $0.10 per share for the fiscal year. We point out that our net income is also heavily affected by a sizable non-cash dot - - comp expense because we believe it is appropriate to incentivize our personnel and line them with our shareholders. All of our employees have a stake in the Company.

Other highlights, we lowered our field income/break-even point by 31% over fiscal 2008 and 54% over Q3 - - excuse me, Q1 2008 when we had just production at [Tulles]. During the year into June 30 our lifting costs which include LOE and production taxes and added to our depletion rate gave us a field break-even point of of $28.67of BOE. This compares to our last quarter with Tulles which was $62.31 per BOE, a dramatic improvement. And we look to hold onto those gains but I don't know that we're going to see them, should not see them dramatically reduced in the future. The product prices we received declined 45% in 2009 versus 2008. This was due to a NYMEX declining 50% for oil and 70% for natural gas year-end to year-end. And our fourth fiscal quarter of 2009 our adjusted EBITDA was $0.2 million. This is the standard EBITDA number that we use only adjusted for including interest income in the calculation. This compares to an adjusted EBITDA of $1.2 million for the fourth quarter of 2008, which was the best quarter that we've had in our history.

We ended the year with $7.6 million of working capital, this compared to $13.6 million at June 2008 and essentially was flat compared to March 31 at $7.5 million. Also during the year you know that we repurchased 788,000 shares of our common stock at an average price of $1.12 with transaction costs per share. We believe that our underlying asset potential per share was substantially greater than the price we paid for our shares but at this time we have no plan to repurchase any more common shares. We've protected our short-term investments during a very difficult credit market conditions. This has been consistent with our history before the credit market meltdown occurred. We basically hold shares in treasury fund and insured CD's and banks. Despite substantially lower oil and gas prices that result the in a loss of reserves, we did not have to impair the net book value of our assets and the ceiling test calculated in our June 39 - - June 30, 2009 ceiling test remains substantially greater than the net book value of our oil and natural gas properties net of related deferred income taxes.

Our non-cash stock comp expense of $2.4 million comprised over 40% of our total G&A expenses during the fiscal year ended 2009. I might point out here too that bonuses in 2009 were dramatically reduced to conserve our resources and they were paid in common stock and not cash. We settled the Thomas et al lawsuit at Delhi, a suit that we thought had no merit but has been lingering over us for about three years now. That suit was set to go to trial in front of a jury in the Parrish where the project is located. That Parrish judge is an elected official. But as it turned out, we got a pretty fair shake there. We did not go to trial. And the lawsuit has been settled with all the plaintiffs. We remain debt-free during 2009.

Now looking on 2010, as Bob said, we'll focus on selective low-cost testing and development of our portfolio properties. We plan on upgrading our shallow multi-pay shale gas reserves in Oklahoma. From a financial - - corporate financial standpoint, we look to pursue commercial joint ventures utilizing our proprietary artificial lift technology which we've tested in one well now at Giddings and we look to establish production at Neptune. We're going to be conducting workovers at Giddings to generate net production to cover our overhead and we're going to solicit joint ventures to drill Giddings PUD locations as the markets allow. We will continue to conservatively manage our Company financially, emphasizing on long-term share value over near-term earnings during the current period of low natural gas prices. We'll retain our financial strength and flexibility to ensure that we can obtain and maintain proper value of our core assets. And we will primarily use internally generated funds and our working capital for our fiscal 2010 goals except to the extent that we supplement them with joint venture financing.

We look forward to continued progress at our Delhi EOR project. As Bob mentioned, the operator plans to initiate CO2 injections by the end of this calendar year and first oil production is expected by mid-calendar 2010. We hope at that time to establish proved reserves at Delhi on one of the two methods that Bob mentioned sometime during this fiscal year. As Bob also mentioned, the in the completion of the pipeline, we're pleased to report that as of June 30, 2009 the operators reported that $256 million of capital expenditures had been made on the project, this excludes capitalized interest and the $50 million paid to us. This is a very capital-intensive program and - - we've continued to focus you on the significant PB10 of our reserves at Delhi. But participating shareholders might also look at DNR's cost. When you look at their all-in costs, including capitalized interest, the pipeline and the amounts of capital that are going onto the ground at Delhi, plus the $50 million they paid us, one begins to realize that purchasing our stock represents an extraordinary opportunity to participate in EPM's barrels at a fraction of the operators cost for their share of oil. Where in the oil and gas business can you get a reverse promote on a class asset play like this?

That completes my comments and I'll turn the call back to Bob.

Thanks, Sterling.

Before we take any questions let me just summarize that as we move into our next fiscal year we have a number of really great projects that we're working on. Certainly Delhi is our crown jewel asset and we're very enthusiastic about that coming on line and generating cash flow. We also have a portfolio of attractive other projects that we believe has potential to add tremendous value to the Company. We have a balanced oil and gas upside potential but our current reserves are primarily oil in this particular price environment. Our projects are low-cost, long-life, repeatable joint opportunities or they offer, in Giddings, strong flush production that we can produce when commodity prices are attractive. Now we believe our strategy of generating projects at a nominal cost, applying our engineering and operating expertise and then demonstrating value for full development is a formula that's proven to be successful, and we've shown that in our first four projects. Now I really invite you to see our latest presentation that's available on the website. It gives a little more detail and color to all that Sterling and I have talked about this morning.

Now with that I'll be happy to take any questions.

Thank you. Ladies and gentlemen, at this time we will conduct a question-and-answer session.

(Operator Instructions).

Our first question comes from the line of Phil Mcpherson from Global Hunter Securities. Please go ahead.

Hi, good morning, guys. Great job. Bob, can you just repeat on the Neptune project what the EUR is per location expected.

Sure, Phil. And for anyone listening we offer our congratulations to Phil and his latest family addition.

Thanks, guys. Appreciate it.

Yes. In south Texas, first of all I would like to point out that that field has produced 32 million barrels from 380 wells just on the original primary production. If you run that calculation, you see a number of about 80,000 barrels recovery per well. Now our reserve report assigns 28,000 gross barrels per well on our infill locations, which is roughly 22,000 to 23,000 net to our interest. We believe, and the historical evidence of the infill wells to date suggests that the recovery should be far in excess of that. But for now, until we can prove otherwise, the engineers being conservative, which is what they're supposed to do, and assigning smaller 28,000 gross barrel per well recovery, again 28 gross is roughly 22, 23 net to us.

And what was the - - on the - - on the infill locations, are those going to be existing well bores or new wells, new wells?

The infill wells will all be new well bores.

And what is your - -

Basically you are taking a field that was - - that was developed on ten-acre spacing and we're going to go in in between them on five-acre spacing. The reason that we have confidence is that we had a field over in Louisiana, we called it the [Tulsteranian] Field which was almost exactly identical to this, same kind of high quality reservoir rock, 21 gravity oil associated with water. And that field was taken all the way down to two-acre spacing in order to get full drainage of the reservoir. Here we're just going to five-acre spacing, which is 250% bigger spacing or drainage area. So we're feeling quite comfortable with this program and the upside of it.

And what was the drilling complete costs?

250,000 per well.

Okay. Great. And how deep and is there a name of the formation?

It's about 2,500 feet deep - - and we'll have a little electric sump pump down in the hole. We'll have one disposable well for probably, - - anywhere from six to ten producing wells.

All right. Great. And then - - last year at the Giddings we had about 3 million barrels of probable that we'd talked about.

Right.

And now with - - just the lower prices, is that 3 million still there and the other million I guess the downward revision would drop into the probable category? Is that there's still about 4 million barrels of probable there?

Last year we had 4 million approved and we had 3 million of probable. This year we've got 3, a little over 3 million approved and 1 million of probable. So we've gone from seven down to four of 1P plus 2P. The difference between those two numbers is of course you've got our production of 134 MBOE. But the big change is in the downward revisions of - - due to pricing. The - -

Right.

We lost five locations, five proved locations which were basically 99% gas in the proved category. And the same thing happened on the probable side. We lost, oh, I want to say, like, maybe ten, ten or 12 probable locations that were all - - all gassy.

Got you.

That would be, again, economic and back on our list if gas prices went back up into the high fives or - - say say $6 range because those leases are still intact, we still own the leases. So it's just a - - it's just driven by commodity pricing. I mean the good news is that these aren't wells that were economic because of $13 gas. They're economic because of gas prices of - - $6. So we think they're still a great asset. We just can't - -

Yes.

Call them a reserve right now.

And on the - - on the earlier ones, was production ahead of expectations? Do you get any kind of - - upward revision on some of those at all?

We did. We had some upward revisions on some wells, and - - and some downward, as you might expect. That's the usual thing that happens. The - - actually I would - - it's hard to really talk about - - the two wells that we drilled in January, we did not have enough production history for the engineer to really make any significant change in his original estimates on those. The one well we drilled has been just outstanding, and is being - - is doing far better than we expected. And the other one is pretty much on expectations. So I suspect that we'll see some upward revisions on that well going forward, but that's - - that's a long time from now.

Great, thanks, guys. I appreciate the color.

Thanks, Phil.

Thank you. And our next question comes from the line of John Kohler, Private Investor. Please go ahead.

Good morning.

Good morning, John. How are you?

Good. How are you?

Good.

Good. Two questions, if I could. I was wondering if any of the Giddings was Eagleford perspective. I know there's been some other people in the area who have been talking about that possibility. And I was wondering if your acreage had anything there. And the second was on the completion technology, or the artificial lift technology, rather, sounds pretty fascinating. Just wondered if you could give some color on that.

Sure. The Eagleford definitely extends all throughout the Giddings Field. Everyone knows that it's there. It is widely considered to be the source rock for the - - for the Giddings Field in terms of the [chalk] and the Georgetown. There have been some - - some drilling activity that hadn't got a lot of press. There's considerable expectation that the Eagleford development will extend into the Giddings Field area from its current location which is to the southwest. But I think that it would be dangerous to try to predict anything from that. I think there - - there's that potential there. We know the Eagleford is there. Whether or not it is a commercial reservoir is - - has yet to be determined. We certainly are watching developments very closely. And we're loathe to part with that potential any time soon. All I can say is that we're watching it carefully.

On the artificial lift, again if you go to the presentation there is a little cartoon slide that shows what we're talking about. But this is technology that we have developed and which we believe is proprietary. We've got patent application in. But it's for horizontal wells where production is either oil production or it's gas production with additional fluid. And the reason is that when you have horizontal wells with the fluid productions of that type, you first produce them under primarily production, they just flow on their own. And then once you can't flow them you typically put in gas lift. Once you can't use gas lift, then you put in a rod pump, which is a mechanical artificial lift. You actually have a pump down the hole but you can't stick that pump into the horizontal section, you can only keep it in the vertical section. So once the fluid level falls to that pump level, you can no longer be effective at pumping out any fluid and therefore, the pump locks up and the well is basically toast. You've got to plug and abandon it.

What we have is a technology that mobilizes fluid from the lowest level in the horizontal sections up to where the pump is located in the vertical section. It's a very, very simple concept and what's difficult is how you actually put that into play. We have put that into a process of - - some specific tools to make this happen. We've actually applied it in one of our wells, it was a - - that was probably our very worst well that we drilled, that it was totally nonproductive and at the time. And then we converted that from not being able to produce to a well that's now productive at the rate of about 27 BOE a day, a very commercial well. So we're very excited about it. But, again, there's a little bit of cautionary note. We've only shown it works in one well and one field and one reservoir. Our goal for this year is to demonstrate that it works in somebody else's wells, and then the next step is to show that it works in other fields. And once we've done those two things we think that we have commercialized the technology and can then look at how to best take advantage of that - - of that technology.

Okay. Is the - - you don't have to utilize any expensive materials or anything like that then in the - -

No.

Okay.

No. There's no - - it's not rocket science. It's just clever engineering and thought process.

Okay. And then I guess to follow-up on the Giddings, there's been a number of sales, somewhat small, that have gone on. If you got the right price, would you consider letting the whole thing go?

I think that that would apply to any asset we have. I mean at the right price, everything is always for sale. With the caveat that - - what's in the best interest of the shareholder?

Okay. Thank you.

Okay. Thanks, John.

Thank you. (Operator Instructions). And our next question comes from the line of Lee Curry from [Gorella]. Please go ahead.

Good morning, Bob.

Lee.

Just wanted to ask you a question about the origin of the Delhi Field project. If I remember the numbers correctly - - you paid something like $2 million or $3 million for your initial interest in it and you spent another $2 million or $3 million the next year in 2004. And then you sold it to Denbury for $50 million. And now D&M tells you that it is worth another $195 million. I would be interested in just a little history lesson on how you found the Delhi Field, where it came from, how long it took you to analyze it, sort of what your thought process was at the time?

Sure. No problem, Lee. The - - of course historically the field was discovered back in the 1940's, it was rapidly developed over a period of years with about 450 wells. It's produced on the order of about 190 million barrels of oil, fully unitized in the 1950's for pressure maintenance, reached its peek and then quickly started dropping off in the 1980's, sold by the two principal owners in the early 1990's, went through hands of several increasingly smaller independent operators. When I first started the Company up in 2003 we were looking for a first project and a project that had the opportunity for us to go in and identify additional potential to use our engineering expertise to develop additional reserves. In this particular case we looked at it - - I should say "we," I was a one-man Company back when we first started. But you look at Delhi, and first of all it covers some 13,000 acres fully unitized. So the first clue was, well where can you get 13,000 acres in a unit anywhere in the oil patch for that kind of money.

Second, we had looked at the prior results the field had been producing, hit maturity and then mostly abandoned when oil prices were fairly low. So there were opportunities for bringing wells back online, for re-entering. The nature of the geology and the structure meant that we had identified a number of opportunities, what we call [added] reserves that we could go in and drill some new wells. And then last we knew that because it had been a pressure maintenance project, that there was additional potential for both secondary and additional enhanceable recovery down the road when oil prices improved. At that time oil prices were around $25, $26 per barrel. And that was the thought process. Real simple is any field that had produced 200, 190 million barrels of oil, it had over 400 million of - - million barrels original in place, all we had to do was to figure out how to get an additional 1% or 2% out of the ground and it would be a huge success for us.

Now as oil prices started to improve, that started opening up new opportunities. And then the second thing that we did was in the process of going through all 450 well files looking for opportunities, we came across these three pieces of paper, one in each - - three well files where the operator had, in 1985, done a simple dump flow of CO2, just came in with a truckload of CO2, dumped it in a well, shut in for 30 days, turned it back on and when they did, son of a gun, if water production went down, oil production went up, very positive response for CO2. So that kind of kicked off some ideas. And that's why we said, well, let's see if there's some CO2 operators out there that might be interested in the project and so that is how we got to Denbury.

Thank you very much. A real - - a real success story.

Thanks, Lee.

Thank you. (Operator Instructions).

Sir, I'm showing that we have no further questions at this time. I'll hand it back to management for any closing remarks.

All right, thanks everyone for participating today. Good questions as usual. I would like to thank you for your time this morning and certainly feel free to check our website for further information and updates or to call Sterling and myself for any additional clarifications or questions you might have. Again, thanks and good morning to you.

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation. You may now disconnect.